Obsidian Energy Announces Third Quarter 2022 Results and Updated 2022 Guidance

  • Third quarter average production increased 24 percent to 29,985 boe/d from 2021 with current production over 33,000 boe/d
  • Continued net debt reduction to $323.1 million from $428.1 million at September 30, 2021, including repayment of the $30.0 million non-revolving term loan
  • Peace River acquisition of additional 10 sections of land and Seal 9-15 gas plant, providing for additional Bluesky and Clearwater development
  • 2023 guidance and shareholder return of capital intentions to be announced in mid-December

Calgary, Alberta--(Newsfile Corp. - November 8, 2022) - OBSIDIAN ENERGY LTD. (TSX: OBE) (NYSE American: OBE) ("Obsidian Energy", the "Company", "we", "us" or "our") is pleased to report operating and financial results for the third quarter of 2022.



Three months ended
September 30


Nine months ended
September 30


 2022

2021

2022

2021 
FINANCIAL1











(millions, except per share amounts)











Cash flow from operating activities
121.4

65.5

330.3

136.1
Basic per share ($/share)2
1.48

0.88

4.03

1.83
Diluted per share ($/share)2
1.44

0.85

3.92

1.78
Funds flow from operations3
104.6

59.3

340.2

137.9
Basic per share ($/share)4
1.27

0.79

4.16

1.86
Diluted per share ($/share)4
1.24

0.77

4.04

1.81
Adjusted Funds flow from operations3
107.4

61.7

365.5

151.6
Basic per share ($/share)4
1.31

0.82

4.46

2.04
Diluted per share ($/share)4
1.27

0.80

4.34

1.99
Net income
40.7

46.6

178.4

392.3
Basic per share ($/share)
0.50

0.62

2.18

5.28
Diluted per share ($/share)
0.48

0.60

2.12

5.14
Capital expenditures
74.0

45.1

217.7

96.1
Decommissioning expenditures
3.5

1.6

15.8

5.4
Long-term debt
253.7

397.0

253.7

397.0
Net debt3
323.1

428.1

323.1

428.1


 

 

 

 
OPERATIONS
 

 

 

 
Daily Production
 

 

 

 
Light oil (bbl/d)
11,062

10,314

11,480

10,389
Heavy oil (bbl/d)
5,854

2,688

5,940

2,712
NGL (bbl/d)
2,379

2,213

2,405

2,144
Natural gas (mmcf/d)
64

54

63

53 
Total production5 (boe/d)
29,985

24,164

30,324

24,017 

 

Average sales price 2,6











Light oil ($/bbl)
118.66

84.27

125.99

76.35
Heavy oil ($/bbl)
81.78

60.87

91.19

49.94
NGL ($/bbl)
69.12

52.79

73.38

43.64
Natural gas ($/mcf)
5.31

3.89

5.90

3.44


 

 

 

 
Netback ($/boe)
 

 

 

 
Sales price
76.58

56.21

83.64

50.11
Risk management loss
(0.59)
(0.93)
(3.92)
(1.27)
Net sales price
75.99

55.28

79.72

48.84
Royalties
(14.06)
(5.99)
(13.71)
(4.56)
Net operating costs4
(14.57)
(13.28)
(14.17)
(13.50)
Transportation
(3.18)
(2.41)
(3.08)
(2.05)
Netback4 ($/boe)
44.18

33.60

48.76

28.73 

 

(1) We adhere to generally accepted accounting principles ("GAAP"); however, we also employ certain non-GAAP measures to analyze financial performance, financial position, and cash flow, including funds flow from operations, adjusted funds flow from operations, net debt, netback and net operating costs. Additionally, other financial measures are also used to analyze performance. These non-GAAP and other financial measures do not have any standardized meaning prescribed by International Financial Reporting Standards ("IFRS") and therefore may not be comparable to similar measures provided by other issuers. The non-GAAP and other financial measures should not be considered to be more meaningful than GAAP measures which are determined in accordance with IFRS, such as net income (loss) and cash flow from operating activities, as indicators of our performance.
(2) Supplementary financial measure. See "Non-GAAP and Other Financial Measures".
(3) Non-GAAP financial measure. See "Non-GAAP and Other Financial Measures".
(4) Non-GAAP financial ratio. See "Non-GAAP and Other Financial Measures".
(5) Please refer to the "Oil and Gas Information Advisory" section below for information regarding the term "boe".
(6) Before risk management gains/(losses).

Detailed information can be found in Obsidian Energy's unaudited consolidated financial statements and management's discussion and analysis ("MD&A") as at and for the three and nine months ended September 30, 2022, on our website at www.obsidianenergy.com, which will be filed on SEDAR and EDGAR in due course.

KEY THIRD QUARTER 2022 RESULTS

With active drilling and completions in all the Company's core areas, third quarter production increased 24 percent to 29,985 boe/d over 2021, and further grew to over 33,000 boe/d currently with the addition of seven new wells (6.8 net) on production in the fourth quarter. Higher production and commodity prices in the third quarter resulted in a 76 percent increase in funds flow from operations ("FFO") from the third quarter of 2021 and generated positive free cash flow of $27.1 million. During the third quarter and into the fourth quarter, we achieved strong production results from our ongoing development program, reduced our net debt, successfully acquired additional land for prospective Bluesky, Clearwater and Cardium opportunities, purchased a key gas plant in Peace River to secure future offtake capacity and commenced exploration drilling in our highly prospective Clearwater play.

2022 Third Quarter Financial Highlights

  • Strong Funds Flow - FFO increased 76 percent to $104.6 million ($1.27 per basic share) for the quarter compared to $59.3 million ($0.79 per basic share) in the third quarter of 2021, largely due to the higher commodity price environment and increased production levels.

  • Capital Development Growth - The Company began second half development activities in all areas during the third quarter, resulting in capital expenditures of $74.0 million (2021 - $45.1 million) and decommissioning expenditures of $3.5 million (2021 - $1.6 million).

  • Continued Debt Reduction - Strong free cash flow generation and our continued focus on reducing debt resulted in a decrease in net debt by 25 percent to $323.1 million at September 30, 2022, from $428.1 million at September 30, 2021. We completed our refinancing that incorporated both senior and subordinated debt during the quarter, resulting in a more favourable debt structure for the Company (see 'Debt Refinancing').

  • Net Operating Costs - Net operating costs of $14.57 per boe in the third quarter of 2022 were higher than in 2021 or the second quarter of 2022, largely from higher power and fuel costs due to rate increases, particularly in August and September.

  • G&A Costs - General and administrative ("G&A") costs were lower at $1.73 per boe in the third quarter of 2022 compared to $1.82 per boe for the same period in 2021.

  • Net Income - Continued strong commodity prices contributed to net income of $40.7 million ($0.50 per basic share) for the third quarter of 2022 compared to net income of $46.6 million ($0.62 per basic share) in the comparable period of 2021. In the third quarter of 2021, net income was aided by an impairment reversal of $26.5 million in our Peace River area, which was mainly due to our acquisition of the remaining 45 percent ownership in the Peace River Oil Partnership.

2022 Third Quarter Operational Highlights

  • Production Levels - Average production was 29,985 boe/d, a 24 percent increase from 24,164 boe/d in the third quarter of 2021.

  • Second Half Development Program - Although development activities were delayed due to wet weather conditions in July, the Company successfully drilled 13 wells (12.8 net) with 11 wells (11.0 net) completed and brought on stream, including eight Viking wells (8.0 net) drilled in our first half development program.

  • Peace River Acquisition - We purchased the Seal 9-15 gas plant within our core Peace River asset during the quarter. This acquisition contributes to our dominant infrastructure position in the area (70 percent of the total area gas processing capacity), providing capacity for future development and expected strong future cash flow through third-party processing fees.

  • Turnaround and Facility Expansion - In September, we completed a major turnaround at our Pembina Lodgepole gas plant and oil battery. In parallel, we executed a low-cost expansion project that increased the facility's capacity by 40 percent (30 percent net), which immediately brought an additional 600 boe/d net production online and created capacity for planned development activity.

  • Continued Focus on Decommissioning Liabilities Reduction - With continued decommissioning work, we are on track to meeting our goal of abandoning over 270 net wells and over 500 kilometres of pipelines (net) in 2022.

2022 Highlights Subsequent to the Quarter

  • Acquired Additional Peace River Land - In October 2022, we purchased an additional 10 sections (approximately 6,400 acres) of prospective Clearwater and Bluesky rights from the Alberta land sale in the Peace River region for a consideration of $4.0 million, further expanding our ownership in the area.

2022 DEVELOPMENT PROGRAM UPDATE

The largest development program that the Company has undertaken in several years, our second half 2022 program is well underway in all our core areas with 13 wells (12.8 net) rig-released in the third quarter: five Cardium wells (4.8 net) in Pembina and Willesden Green, six Bluesky wells (6.0 net) in Peace River, one Mannville gas well (1.0 net) in Willesden Green, and one vertical Devonian well (1.0 net). Of those wells, six wells (6.0 net) are on production in Peace River along with eight Viking wells (8.0 net) that were rig-released in the second quarter of 2022.

Another six wells (6.0 net) were rig-released and nine wells (8.8 net) brought on production in October, resulting in strong initial production ("IP") rates in the Peace River and Willesden Green areas. With a second rig now drilling in the Peace River area, we are focused on completing the drilling of the remainder of the 35 well (33.9 net) second half program by year-end. In total, we expect 65 wells (63.4 net) will be rig-released in 2022, of which 52 wells (50.7 net) are expected to be on production by the end of the year.

Peace River

In the third quarter, we rig-released six Bluesky wells (6.0 net) from our second half 2022 program, with an additional two Bluesky wells (2.0 net) rig-released in October. Three wells (3.0 net) were on production in the third quarter; the remaining five wells (5.0) are expected to come on production throughout the fourth quarter. Results are in line with expectations with six of the recent wells drilled on production at ~800 boe/d (98 percent heavy oil) in total. Some of these wells are producing through rate limited temporary production facilities to accelerate clean-up times; production rates will continue to strengthen as the wells transition to higher oil rates. In addition, we began drilling the first well (1.0 net) of the remaining five Bluesky wells (5.0 net) to be drilled in the fourth quarter.

While testing an edge location of a producing pool, we encountered reservoir stability issues resulting in low productivity on a single two-well pad drilled late in the first half of 2022, which is reflected in our updated production guidance (see 'Updated 2022 Guidance'). The information gathered during the drilling of this pad has been incorporated into our mapping and future inventory locations.

In late October 2022, we furthered the delineation and exploration of our land base with the spud of the first of two wells (2.0 net) targeting the Clearwater play; our second well is expected to spud in December. As part of our larger exploration process, these wells will provide key information towards an extensive 2023 Clearwater exploration program. Both wells will be evaluated and tested in late 2022 and early 2023, respectively. In parallel with the Bluesky, our Clearwater acreage offers significant exploration and development upside with identified drilling opportunities, and represents a compelling risked value opportunity.

During the third quarter, we purchased the Seal 9-15 gas plant in Peace River, contributing to our dominant infrastructure position in the area (approximately 70 percent of the total area gas processing capacity) while providing expected strong future cash flow through third-party processing fees. The Seal gas plant has approximately 10 mmcf/d of capacity and is currently operating at about 65 percent capacity. Obsidian Energy currently delivers less than 1 mmcf/d of gas to the facility, leaving ample room for our near term and future development programs. Ownership of this plant combined with our existing infrastructure solidifies Obsidian Energy's unique position compared to peers in this increasingly competitive development area. The acquisition supports our long-term Environmental, Social and Governance strategy of minimizing flaring and emissions, and aides in meeting provincial gas conservation regulations unique to this area. The Company currently conserves over 95 percent of gas in the Peace River area.

In October 2022, we increased our substantial land position in the Peace River area with the purchase of 10 sections (approximately 6,400 acres) of prospective Bluesky and Clearwater rights at the Alberta land sale for a consideration of approximately $4.0 million. The Company has identified 51 potential Bluesky locations and 32 potential Clearwater opportunities on this newly acquired acreage through technical evaluation of the parcels. In total, we have acquired 33.5 sections for a total consideration of $17.9 million in 2022. This brings our total land ownership to 497 sections of heavy oil rights in Peace River. Through the 2022 land sales acquisitions, Obsidian Energy estimates that it has added a total of 79 potential Bluesky locations and 46 potential Clearwater opportunities.

Willesden Green

Willesden Green continues to provide high quality economic development across multiple formations for the Company. During the third quarter, Obsidian Energy drilled four wells (4.0 net) targeting the Cardium formation and one liquids-rich Mannville well (1.0 net). Currently, four wells (4.0 net) are on production, providing excellent rates and robust economic returns. The two wells at the Crimson 3-03 Pad are meeting expectations and capital efficiencies for top tier Cardium development with average IP 30-day rates of 597 boe/d (69 percent oil) per well. The third well on the 4-17 Pad surpassed internal expectations with peak daily production rates of 698 boe/d (84 percent oil). The Mannville gas well is still in early production with a peak daily rate of 1,158 boe/d (16 percent oil). We expect to complete the drilling of three additional wells in our Willesden Green area during the remainder of 2022.

Pembina

The two Cardium wells (1.8 net) on the 16-09 Pad were drilled and rig released during the third quarter. Online in early October, total pad production is currently approximately 560 boe/d (72 percent oil) as the wells continue to clean up and improve. In addition, one exploration vertical Devonian well (1.0 net) was drilled and is currently under evaluation during the quarter. Drilling of the final well on the three-well 14-6 Pad in South Lodgepole is being completed, and we expect to finish drilling three additional Cardium wells (2.7 net) and one vertical Devonian well (0.5 net) by year-end.

Viking

All eight (8.0 net) wells from our first half Viking program are on production, adding a peak total rate of over 1,000 boe/d to the Esther field. As part of this program the Company drilled a step-out well to test the western extent of the play, which displayed peak and last 60-day production rates of 242 boe/d (88 percent oil) and 211 boe/d (86 percent oil), respectively, and exhibits minimal decline. As one of the most prolific Viking wells drilled in the area, it provides an outstanding economic return and effectively delineates the area, opening multiple additional development locations on our extensive land position.

DEBT REFINANCING

On July 27, 2022, we completed a private placement issuance of senior unsecured notes and entered into new syndicated credit facilities providing a more favourable debt structure with long-term debt capital and credit facilities to meet our ongoing operational liquidity needs. The refinancing was composed as follows:

  • Senior Unsecured Notes: We issued five-year senior unsecured notes (the "Notes") in the amount of $127.6 million (the "Offering") at a rate of 11.95 percent due on July 27, 2027.

  • New Credit Facilities: The Company entered into new syndicated credit facilities with borrowing capacity of $205.0 million (the "New Credit Facilities"), consisting of $175.0 million revolving syndicated credit facilities (the "New Syndicated Facilities") and a $30.0 million non-revolving term loan (the "New Term Loan"). The New Term Loan was fully repaid in September 2022 from free cash flow from our operations.

  • Debt Repayment: Upon completion of the Offering, we repaid all our previous senior secured notes due November 30, 2022, the outstanding balances under our previous credit facilities due November 30, 2022, and the PROP limited recourse loan due on December 31, 2022. In addition, the Company also closed out hedges that were put in place for the PROP 45 limited recourse financing (US$3.4 million loss) and paid fees associated with the refinancing ($6.5 million).

2022 UPDATED GUIDANCE

Our 2022 guidance has been updated to capture our latest production estimates that incorporate several strategic and investment decisions. A prolonged break-up period due to excessively wet ground conditions delayed the start of our second half development operations in Central Alberta. The Company chose to focus on capital efficiency rather than incur significant additional costs to enforce a premature start. Our updated guidance incorporates this modified second half development program, including on-stream production delays, recent strong well results, lower than expected results on one Peace River pad from the first half of 2022 (see "Peace River') and our 2022 development program adjustment to 65 wells (63.4 net) from a total of 68 wells (65.0 net) for the year.

Production guidance has been lowered by approximately three percent to 31,000 boe per day (at the midpoint), representing a 26 percent increase over 2021, with associated adjustments to net operating costs and general and administrative expenses on a per boe basis. Operating cost guidance reflects the impact of higher than anticipated third quarter electrical power rates and additional inflationary pressures. Our capital expenditures guidance has been increased to account for: incremental success in land sale activity in our Clearwater, Bluesky and Cardium plays; acquisition of the Seal 9-15 gas plant; accelerated exploration investment in our Clearwater holdings; higher working interest in certain operated projects; incremental non-operated activity; and inflationary pressures. Regarding 2023, the Company is currently reviewing our program and, once the 2023 capital budget has been approved (which is expected to occur in mid-December) detailed guidance will be provided, which will supersede our previously disclosed preliminary 2023 forecast. With the release of our 2023 guidance, we also expect to announce our intentions regarding our shareholder return of capital plans. Our updated 2022 guidance is presented below.



2022E Previous
Guidance
2022E Updated
Guidance
Production1boe/d31,500 - 32,50030,800 - 31,200
% Oil and NGLs
66%65%
Capital expenditures$ millions295 - 305320 - 330
Decommissioning Expenditures2$ millions1718
Net operating costs$/boe12.70 - 13.5013.50 - 14.00
General & administrative$/boe1.45 - 1.551.55 - 1.65
   
Based on midpoint of above guidance

WTI Range3US$/bbl90.00 - 120.0085.00 - 95.00
AECO Range3CAD$/GJ5.50 - 7.505.80
FFO$ millions455 - 580441 - 456
Adjusted FFO4$ millions499 - 624487 - 502
Free cash flow 4$ millions137 - 26298 - 113
Net debt5$ millions257 - 132335 - 320
Net debt to FFO4,5times0.6x - 0.2x0.8x - 0.7x

 

1) Mid-point of 2022E updated guidance range: 11,715 bbl/d light oil, 6,065 bbl/d heavy oil, 2,475 bbl/d NGLs and 64.5 mmcf/d natural gas. Mid-point of 2022E previous guidance of 12,350 bbl/d light oil, 6,325 bbl/d heavy oil, 2,525 bbl/d NGLs and 64.6 mmcf/d natural gas. Average production volumes in 2022 do not include any forecasted production associated with Clearwater exploratory capital expenditures.
2) Decommissioning expenditures do not include grants and allocations to be utilized by the Company under the Alberta Site Rehabilitation Program ("ASRP").
3) 2022E updated guidance pricing assumptions are for November to December. Mid-point pricing assumptions for our 2022E updated guidance include WTI at US$90.00/bbl and AECO at $5.80/GJ from November to December; and for our 2022E previous guidance was WTI at US$105.00/bbl and AECO at $6.50/GJ from July to December.
4) Pricing assumptions for our 2022E updated guidance outlined are forecasted for November and December 2022 and includes risk management (hedging) adjustments as of November 4, 2022. Guidance FFO and free cash flow ("FCF") includes approximately $46 million of estimated charges for 2022 related to the deferred share units, performance share units and non-treasury incentive plan awards share-based compensation amounts which are based on a share price of $15.00 per share. The charge is primarily due to the Company's increased share price in 2022 compared to the closing price on December 31, 2021, of $5.21 per share. Adjusted FFO excludes the estimated non-cash share-based compensation amounts for 2022.
5) Net debt figures estimated as at December 31, 2022.

HEDGING UPDATE

The Company continues to focus our hedging program on near term WTI positions to protect cashflow given our first half capital program. As at November 7, 2022, the following financial oil and gas contracts are in place on a weighted average basis:

WTI Oil Contracts

TypeRemaining Term
Volume
(bbls/d)


Bought Put
Price
(C$/bbl)


Sold Call
Price
(C$/bbl)


Swap Price (C$/bbl) 
WTI CollarOctober 2022
10,000

109.75

130.07

-
WTI SwapNovember 2022
1,950

 

 

123.97
WTI CollarNovember 2022
7,000

106.07

126.77

-
WTI CollarDecember 2022
2,000

105.00

130.20

- 

 

AECO Natural Gas Contracts

TypeRemaining Term 
Volume
(mcf/d)


Swap Price
(C$/mcf)
 
AECO SwapOctober 2022 
26,065

4.74
AECO SwapApril 2023 - October 2023 
17,487

4.01 

 

UPDATED CORPORATE PRESENTATION

For further information on these and other matters, Obsidian Energy will post an updated corporate presentation later today on our website, www.obsidianenergy.com.

ADDITIONAL READER ADVISORIES

OIL AND GAS INFORMATION ADVISORY

Barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of crude oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is misleading as an indication of value.

TEST RESULTS AND INITIAL PRODUCTION RATES

Test results and initial production rates disclosed herein, particularly those short in duration, may not necessarily be indicative of long-term performance or of ultimate recovery. Readers are cautioned that short term rates should not be relied upon as indicators of future performance of these wells and therefore should not be relied upon for investment or other purposes. A pressure transient analysis or well-test interpretation has not been carried out and thus certain of the test results provided herein should be considered preliminary until such analysis or interpretation has been completed.

NON-GAAP AND OTHER FINANCIAL MEASURES

Throughout this news release and in other materials disclosed by the Company, we employ certain measures to analyze financial performance, financial position, and cash flow. These non-GAAP and other financial measures do not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures provided by other issuers. The non-GAAP and other financial measures should not be considered to be more meaningful than GAAP measures which are determined in accordance with IFRS, such as net income (loss) and cash flow from operating activities as indicators of our performance. The Company's unaudited consolidated financial statements and management's discussion and analysis ("MD&A") as at and for the three and nine months ended September 30, 2022 are available on the Company's website at www.obsidianenergy.com and under our SEDAR profile at www.sedar.com. The disclosure under the section "Non-GAAP and Other Financial Measures" in the MD&A is incorporated by reference into this news release.

Non-GAAP Financial Measures

The following measures are non-GAAP financial measures: FFO; adjusted FFO; net debt; net operating costs; netback; and FCF. These non-GAAP financial measures are not standardized financial measures under IFRS and might not be comparable to similar financial measures disclosed by other issuers. See the disclosure under the section "Non-GAAP and Other Financial Measures" in our MD&A for the three and nine months ended September 30, 2022, for an explanation of the composition of these measures, how these measures provide useful information to an investor, and the additional purposes, if any, for which management uses these measures.

For a reconciliation of FFO to cash flow from operating activities, being our nearest measure prescribed by IFRS, see "Non-GAAP Measures Reconciliations" below.

For a reconciliation of adjusted FFO to cash flow from operating activities, being our nearest measure prescribed by IFRS, see "Non-GAAP Measures Reconciliations" below.

For a reconciliation of net debt to long-term debt, being our nearest measure prescribed by IFRS, see "Non-GAAP Measures Reconciliations" below.

For a reconciliation of net operating costs to operating costs, being our nearest measure prescribed by IFRS, see "Non-GAAP Measures Reconciliations" below.

For a reconciliation of netback to sales price, being our nearest measure prescribed by IFRS, see "Non-GAAP Measures Reconciliations" below.

For a reconciliation of FCF to cash flow from operating activities, being our nearest measure prescribed by IFRS, see "Non-GAAP Measures Reconciliations" below.

Non-GAAP Ratios

The following measures are non-GAAP ratios: funds flow from operations (basic per share ($/share) and diluted per share ($/share)), which use funds flow from operations as a component; net operating costs ($/boe), which uses net operating costs as a component; netback ($/boe), which uses netback as a component. These non-GAAP ratios are not standardized financial measures under IFRS and might not be comparable to similar financial measures disclosed by other issuers. See the disclosure under the section "Non-GAAP and Other Financial Measures" in our MD&A for the three and nine months ended September 30, 2022, for an explanation of the composition of these non-GAAP ratios, how these non-GAAP ratios provide useful information to an investor, and the additional purposes, if any, for which management uses these non-GAAP ratios.

Supplementary Financial Measures

The following measures are supplementary financial measures: average sales price; cash flow from operating activities (basic per share and diluted per share); and general and administrative costs ($/boe). See the disclosure under the section "Non-GAAP and Other Financial Measures" in our MD&A for the three and nine months ended September 30, 2022, for an explanation of the composition of these measures.

Non-GAAP Measures Reconciliations

2022 and 2021 Cash Flow from Operating Activities, Funds Flow from Operations and Free Cash Flow


Three months ended
September 30

Nine months ended
September 30
 
(millions, except per share amounts)2022
2021
2022
2021 
Cash flow from operating activities$121.4
$65.5
$330.3
$136.1
Change in non-cash working capital
(21.9)
(9.1)
(13.9)
(1.1)
Decommissioning expenditures
3.5

1.6

15.8

5.4
Onerous office lease settlements
2.3

2.3

6.9

7.0
Deferred financing costs
(0.7)
(1.7)
(2.1)
(4.4)
Financing fees paid
-

-

-

4.4
Restructuring charges (1)
-

0.1

2.5

(1.8)
Transaction costs
-

-

0.1

-
Other expenses (1)
-

0.6

0.6

(7.7)
Funds flow from operations
104.6

59.3

340.2

137.9 
Share based compensation (2)
2.8

2.4

25.3

13.7 
Adjusted Funds flow from operations
107.4

61.7

365.5

151.6
Share based compensation (2)
(2.8)
(2.4)
(25.3)
(13.7)
Capital expenditures
(74.0)
(45.1)
(217.7)
(96.1)
Decommissioning expenditures
(3.5)
(1.6)
(15.8)
(5.4)
Free Cash Flow$27.1
$12.6
$106.7
$36.4 

 

(1) Excludes the non-cash portion of restructuring and other expenses.
(2) Includes expenses associated with our cash settled share-based incentive plans, being the Deferred Share Unit Plan, Performance Share Unit Plan and the Non-Treasury Incentive Award Plan.

2022 and 2021 Netback to Sales Price

Three Months Ended
Nine Months Ended

September 30
September 30 
(millions)2022
2021
2022
2021 




Sales price$76.58
$56.21
$83.64
$50.11
Risk management loss
(0.59)
(0.93)
(3.92)
(1.27)
Net sales price
75.99

55.28

79.72

48.84
Royalties
(14.06)
(5.99)
(13.71)
(4.56)
Net operating costs
(14.57)
(13.28)
(14.17)
(13.50)
Transportation
(3.18)
(2.41)
(3.08)
(2.05)
Netback$44.18
$33.60
$48.76
$28.73 

 

2022 and 2021 Net Operating Costs to Operating Costs

Three Months Ended
Nine Months Ended

September 30
September 30 
(millions)2022
2021
2022
2021 
Operating costs$43.5
$32.3
$127.7
$97.1
Less processing fees
(1.6)
(1.6)
(5.5)
(4.9)
Less road use recoveries
(1.8)
(1.2)
(4.9)
(3.7)
Net operating costs$40.1
$29.5
$117.3
$88.5 

 

2022 and 2021 Net Debt to Long-Term Debt

 



As at 
(millions)
September 30, 2022

December 31, 2021 
Long-term debt





Syndicated credit facility$134.0
$321.5
Senior unsecured notes
127.6

-
Senior secured notes
-

54.9
PROP Limited recourse loan
-

16.0
Deferred interest
-

1.3
Unamortized discount of senior unsecured notes
(2.4)
-
Deferred financing costs
(5.5)
(2.7)
Total
253.7

391.0


 

 
Working capital deficiency
 

 
Cash
-

(7.3)
Accounts receivable
(79.6)
(68.9)
Prepaid expenses and other
(14.7)
(9.1)
Accounts payable and accrued liabilities
163.7

107.8 
Total
69.4

22.5


 

  
Net debt $323.1
$413.5 

 

ABBREVIATIONS

Oil Natural Gas
bblbarrel or barrelsmcf thousand cubic feet
bbl/dbarrels per daymmcfmillion cubic feet
boebarrel of oil equivalentmmcf/d million cubic feet per day
boe/dbarrels of oil equivalent per dayAECOAlberta benchmark price for natural gas
MSWMixed Sweet Blend NGLnatural gas liquids
WTIWest Texas Intermediate

 

FUTURE-ORIENTED FINANCIAL INFORMATION

This release contains future-oriented financial information ("FOFI") and financial outlook information relating to the Company's prospective results of operations, operating costs, expenditures, production, FFO, adjusted FFO, FCF, net operating costs, and net debt, which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth below under "Forward-Looking Statements". The Company's actual results, performance or achievement could differ materially from those expressed in, or implied by, such FOFI, or if any of them do so, what benefits the Company will derive therefrom. The Company has included this FOFI to provide readers with a more complete perspective on the Company's business as of the date hereof and such information may not be appropriate for other purposes.

FORWARD-LOOKING STATEMENTS

Certain statements contained in this document constitute forward-looking statements or information (collectively "forward-looking statements") within the meaning of the "safe harbour" provisions of applicable securities legislation. Forward-looking statements are typically identified by words such as "anticipate", "continue", "estimate", "expect", "forecast", "budget", "may", "will", "project", "could", "plan", "intend", "should", "believe", "outlook", "objective", "aim", "potential", "target" and similar words suggesting future events or future performance. In addition, statements relating to "reserves" or "resources" are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated and can be profitably produced in the future. In particular, this document contains forward-looking statements pertaining to, without limitation, the following: that we will file the unaudited consolidated financial statements and MD&A on our website, SEDAR and EDGAR in due course; expectations for future development capacity and third-party processing fees due to the Seal 9-15 gas plant purchase; that we will meet out decommissioning liabilities goal for 2022; our expectations of potential drilling opportunities in the Bluesky and Clearwater; our development program; our expected spud and on-stream dates; our 2022 updated guidance for production, capital and decommissioning expenditures, net operating costs and general & administrative costs, FFO, adjusted FFO, FCF, net debt and net debt to FFO; the expected timing for 2023 guidance disclosure and intentions regarding our shareholder return of capital plans; our hedges; and our expectations for an updated corporate presentation.

With respect to forward-looking statements and FOFI contained in this document, the Company has made assumptions regarding, among other things: that the Company does not dispose of or acquire material producing properties or royalties or other interests therein other than stated herein (provided that, except where otherwise stated, the forward-looking statements and FOFI contained herein (including our guidance set out under "2022 Updated Guidance") do not assume the completion of any transaction); the impact of regional and/or global health related events, including the ongoing COVID-19 pandemic, on energy demand and commodity prices; that the Company's operations and production will not be disrupted by circumstances attributable to the COVID-19 pandemic and the responses of governments and the public to the pandemic; global energy policies going forward, including the ability of members of OPEC, and other nations to agree on and adhere to production quotas from time to time; our ability to qualify for (or continue to qualify for) new or existing government programs created as a result of the COVID-19 pandemic (including the Alberta Site Rehabilitation Program) or otherwise, and obtain financial assistance therefrom, and the impact of those programs on our financial condition; our ability to execute our plans as described herein and in our other disclosure documents and the impact that the successful execution of such plans will have on our Company and our stakeholders; future capital expenditure and decommissioning expenditure levels; future operating costs and general & administrative costs; future crude oil, natural gas liquids and natural gas prices and differentials between light, medium and heavy oil prices and Canadian, WTI and world oil and natural gas prices; future hedging activities; future crude oil, natural gas liquids and natural gas production levels; future exchange rates, inflation rates and interest rates; future debt levels; our ability to execute our capital programs as planned without significant adverse impacts from various factors beyond our control, including extreme weather events, such as wild fires and flooding, infrastructure access and delays in obtaining regulatory approvals and third party consents; our ability to obtain equipment in a timely manner to carry out development activities and the costs thereof; our ability to market our oil and natural gas successfully to current and new customers; our ability to obtain financing on acceptable terms, including our ability (if necessary) to continue to extend the revolving period and term out period of our credit facility, our ability to maintain the existing borrowing base under our credit facility, our ability (if necessary) to replace our syndicated bank facility and our ability (if necessary) to finance the repayment of our Notes on maturity; and our ability to add production and reserves through our development and exploitation activities.

Although the Company believes that the expectations reflected in the forward-looking statements and FOFI contained in this document, and the assumptions on which such forward-looking statements and FOFI are made, are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned not to place undue reliance on forward-looking statements and FOFI included in this document, as there can be no assurance that the plans, intentions or expectations upon which the forward-looking statements are based will occur. By their nature, forward-looking statements and FOFI involve numerous assumptions, known and unknown risks and uncertainties that contribute to the possibility that the forward-looking statements and FOFI contained herein will not be correct, which may cause our actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements and FOFI. These risks and uncertainties include, among other things: the possibility that we change our 2022 budget in response to internal and external factors, including those described herein; the possibility that the Company will not be able to continue to successfully execute our business plans and strategies in part or in full, and the possibility that some or all of the benefits that the Company anticipates will accrue to our Company and our stakeholders as a result of the successful execution of such plans and strategies do not materialize; the possibility that the Company is unable to complete one or more of the potential transactions being pursued, on favorable terms or at all; the possibility that the Company ceases to qualify for, or does not qualify for, one or more existing or new government assistance programs implemented in connection with the COVID-19 pandemic and other regional and/or global health related events or otherwise, that the impact of such programs falls below our expectations, that the benefits under one or more of such programs is decreased, or that one or more of such programs is discontinued; the impact on energy demand and commodity prices of regional and/or global health related events, including the ongoing COVID-19 pandemic, and the responses of governments and the public to the pandemic, including the risk that the amount of energy demand destruction and/or the length of the decreased demand exceeds our expectations; the risk that there is another significant decrease in the valuation of oil and natural gas companies and their securities and in confidence in the oil and natural gas industry generally, whether caused by a resurgence of the COVID-19 pandemic, the worldwide transition towards less reliance on fossil fuels and/or other factors; the risk that the COVID-19 and/or other factors pandemic adversely affects the financial capacity of the Company's contractual counterparties and potentially their ability to perform their contractual obligations; the possibility that the revolving period and/or term out period of our credit facility and the maturity date of our notes is not further extended (if necessary), that the borrowing base under our credit facility is reduced, that the Company is unable to renew or refinance our credit facilities on acceptable terms or at all and/or finance the repayment of our notes when they mature on acceptable terms or at all and/or obtain debt and/or equity financing to replace one or all of our credit facilities and notes; the possibility that we breach one or more of the financial covenants pursuant to our agreements with our lenders and the holders of our notes; the possibility that we are forced to shut-in production, whether due to commodity prices decreasing, extreme weather events or other factors; the risk that OPEC and other nations fail to agree on and/or adhere to production quotas from time to time that are sufficient to balance supply and demand fundamentals for crude oil; general economic and political conditions in Canada, the U.S. and globally, and in particular, the effect that those conditions have on commodity prices and our access to capital; industry conditions, including fluctuations in the price of crude oil, natural gas liquids and natural gas, price differentials for crude oil and natural gas produced in Canada as compared to other markets, and transportation restrictions, including pipeline and railway capacity constraints; fluctuations in foreign exchange or interest rates; the risk that our costs increase significantly due to inflation, supply chain disruptions and/or other factors, adversely affecting our profitability; unanticipated operating events or environmental events that can reduce production or cause production to be shut-in or delayed (including extreme cold during winter months, wild fires and flooding); the risk that wars and other armed conflicts adversely affect world economies and the demand for oil and natural gas, including the ongoing war between Russian and Ukraine; the possibility that fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to hydrocarbons and technological advances in fuel economy and renewable energy generation systems could permanently reduce the demand for oil and natural gas and/or permanently impair the Company's ability to obtain financing on acceptable terms or at all, and the possibility that some or all of these risks are heightened as a result of the response of governments and consumers to the ongoing COVID-19 pandemic and/or public opinion and/or special interest groups. Additional information on these and other factors that could affect Obsidian Energy, or its operations or financial results, are included in the Company's Annual Information Form (See "Risk Factors" and "Forward-Looking Statements" therein) which may be accessed through the SEDAR website (www.sedar.com), EDGAR website (www.sec.gov) or Obsidian Energy's website. Readers are cautioned that this list of risk factors should not be construed as exhaustive.

Unless otherwise specified, the forward-looking statements and FOFI contained in this document speak only as of the date of this document. Except as expressly required by applicable securities laws, we do not undertake any obligation to publicly update or revise any forward-looking statements. The forward-looking statements and FOFI contained in this document are expressly qualified by this cautionary statement.

Obsidian Energy shares are listed on both the Toronto Stock Exchange in Canada and the NYSE American in the United States under the symbol "OBE".

All figures are in Canadian dollars unless otherwise stated.

CONTACT

OBSIDIAN ENERGY
Suite 200, 207 - 9th Avenue SW, Calgary, Alberta T2P 1K3
Phone: 403-777-2500
Toll Free: 1-866-693-2707
Website: www.obsidianenergy.com;

Investor Relations:
Toll Free: 1-888-770-2633
E-mail: investor.relations@obsidianenergy.com

To view the source version of this press release, please visit https://www.newsfilecorp.com/release/143447

info